This invention relates generally to methods and compositions for cementing, and, more specifically to methods and compositions for cementing in cold environments. In particular, this invention relates to methods and compositions for well cementing in permafrost environments utilizing low heat of hydration mixtures of hydraulic cement, aluminum silicate and accelerators.
Cementing is a common technique employed during many phases of wellbore operations. For example, cement may be employed to cement or secure various casing strings and/or liners in a well. In other cases, cementing may be used in remedial operations to repair casing and/or to achieve formation isolation. In still other cases, cementing may be employed during well abandonment. Cement operations performed in wellbores having relatively cold temperatures, i.e., bottomhole circulating temperatures typically less than about 50xc2x0 F., may present particular problems, among other things, in obtaining good wellbore isolation. These problems may be exacerbated in those cases where wellbore and/or formation conditions promote fluid intrusion during or after cement curing, including intrusion of water, gas, or other fluids. Furthermore, relatively cold temperatures may lead to excessive thickening times, resulting in costly delays while waiting on cement to cure (xe2x80x9cWOCxe2x80x9d).
Deepwater well operations typically include operations performed on offshore wells drilled in water depths over about 1,000 feet (especially in Northern latitudes), and more typically, greater than about 2,000 feet deep. Under deepwater conditions, relatively cool temperatures promoted by seawater, in some cases coupled with poorly consolidated formations often make the prevention of fluid intrusion during cementing a challenge. In such cases, relatively cool temperatures (typically less than about 60xc2x0 F., and more typically, less than about 50xc2x0 F.) may slow cement curing or hydration, extending the transition time of a cement slurry. Transition time may be defined as the time required for a cement slurry to develop gel strength, or quantitatively as the time for a cement slurry gel strength to go from 100 lb/100 ft2 to 500 lb/100 ft2.
Because longer transition times means that the gel strength of a cement increases relatively slowly, there is more opportunity for intrusion of water or other fluids, such as oil or gas, to migrate through or displace a cement slurry. When such fluid migration occurs, channels, pockets or other cavities may form in the setting cement. Such cavities or channels may create a permanent flow passage or otherwise compromise the integrity of a cement sheath, such as exists between a pipe string and a formation. Furthermore, intrusion of a fluid such as water may dilute a cement slurry and thus prevent it from developing sufficient compressive strength. Fluid migration into a cement is typically more extensive when cement transition times are lengthened because although the cement column in a wellbore has typically built enough gel strength to support itself and to thereby reduce hydrostatic pressure on the surrounding formation, it has not developed sufficient gel strength to prevent fluid intrusion or migration. Although reduced gel strength, extended transition times, and fluid intrusion during cement curing are problems commonly encountered in deepwater completions, such problems may also be encountered in any wellbore having relatively cool formation temperatures, such as in wellbores drilled in cool or cold climates.
In those cases where formation sands are overpressured by fluids such as gas and/or water, fluid intrusion into the setting cement during the cement transition time may be a particular problem. In this regard, shallow formations in deepwater wells typically are unconsolidated, making them weak, prone to fracture, and prone to producing relatively high flows of water. Such a problem may be further exacerbated in those situations in which a relatively lightweight cement slurry is required. Such situations include those in which formations are susceptible to fracture, such as naturally weak or unconsolidated formations, or those with reduced bottom-hole pressures. Lightweight cements typically have longer transition times at relatively cool formation temperatures. Such cements are often referred to as xe2x80x9cwater extended cement slurries.xe2x80x9d Due to the relatively long transition times of water extended or lightweight cement slurries, there is increased opportunity for fluid intrusion and cement contamination. Such contamination may result in the loss of formation isolation and/or in casing damage. Resulting cement job failures may result in many undesirable consequences, such as the need for expensive remedial work, increased rig time, loss of production, and/or loss of the wellbore itself.
In cold weather regions, such as the Arctic, the temperature of shallow formations may not exceed 32xc2x0 F. for several hundred feet of depth. Such formations are typically referred to as xe2x80x9cpermafrostxe2x80x9d which denotes a permanently frozen subsurface formation. Depending on the location, a permafrost or frozen section may extend from a few feet to depths greater than about 1500 feet. In such situations, even where fluid intrusion is not a problem, a cement slurry may not have the opportunity to set and provide needed strength before it freezes. Conventional methods for downhole cementing in permafrost formations have traditionally employed gypsum/Portland cement blends. As compared to conventional Portland cements, these gypsum/Portland cement blends offer reduced BTU output when hydrated, and therefore reduced degree of permafrost melting during and after cement placement. Gypsum/Portland cement blends are also noted for an ability to set under freezing conditions. The density of conventional gypsum/Portland cement blends typically ranges from about 12.0 pound per gallon (xe2x80x9cppgxe2x80x9d or xe2x80x9cPPGxe2x80x9d) to about 15 ppg. These cement blends typically contain from about 20% by weight of dry blend (xe2x80x9cBWOBxe2x80x9d) to about 40% BWOB Portland cement, and typically suffer from low compressive strength and high cost.
In some wellbores, gas intrusion may be a particular problem during and after cementing. Such wellbores include, for example, those where a wellbore penetrates a gas formation having a pressure corresponding to a first pressure gradient and a relatively underbalanced permeable zone having a pressure corresponding to a second pressure gradient that is lower than the first pressure gradient. In such cases, hydrostatic pressure exerted by the cement slurry may keep gas intrusion from occurring while the cement is still fluid. However, due to chemical hydration of the slurry and/or dehydration of the slurry across the permeable zone, the pore pressure of the slurry may decrease below the gas pressure in the reservoir allowing the gas to enter the cement. This underbalanced pressure may result, for example, in gas channeling to the surface or to another lower pressure permeable zone.
Disclosed are cement compositions and methods which, in one embodiment, may be formulated with aluminum silicate and metal sulfate, such as aluminum sulfate, to achieve improved gel and/or compressive strength characteristics in relatively low temperature environments and/or in relatively short periods of time as compared to conventional well cements. Such cement systems may be characterized by the ability to form cement slurries having relatively short transition times, a characteristic which may be particularly advantageous in cold environments and/or in wellbores having relatively weak formations and fracture gradients, both of which are typically found in deepwater offshore wells. Further, the disclosed cement compositions may be formulated to have reduced heat of hydration as compared to conventional cements, making them well suited for cementing in permafrost environments, or in other cold environments such as those where the soil surface temperature does not exceed 32xc2x0 F. and/or those environments where temperature of shallow formations does not exceed 32xc2x0 F. for about 100 feet or more. In this regard, thawing of frozen formations may, for example, lead to the creation of a water layer between cement and the formation, which may interfere with the cement-to-formation bond. Advantageously, reduced heats of hydration possible with the disclosed cement compositions may reduce or substantially eliminate thawing of permafrost or other frozen formations, and in doing so facilitate formation of better cement bonds between cement and formation. The disclosed cement compositions may also be formulated to have increased compressive strength and/or shortened pump times as compared to conventional cements, while at the same time exhibiting comparable or decreased heat of hydration as compared to such conventional cements.
As disclosed herein, a cementing system may comprise an ASTM Type I cement, or other suitable hydraulic cement, mixed with reactive aluminum silicate (e.g., such as high reactivity, metakaolin) and/or aluminum sulfate. Optional additives to such a cement system include, but are not limited to, quick-setting gypsum, polyvinyl alcohol-based anti-fluid flow additives, accelerators (including calcium chloride and sodium metasilicate), and/or sufficient water to form a pumpable slurry. Such cement systems may be optionally foamed with, for example, nitrogen to produce stable and lightweight cement slurries. Such a slurry may be formulated to develop, in less than about 35 minutes after placement, sufficient static gel strength to inhibit shallow water flow. In addition, such a slurry may obtain an initial compressive strength (e.g., about 50 psi) in less than about ten hours under seafloor conditions.
In one respect then, disclosed are cementing compositions and methods which offer relatively high compressive strength at relatively low densities and superior stability in freeze-thaw cycling, as compared to conventional gypsum/Portland well cements. The disclosed cementing compositions are particularly useful for downhole cementing in permafrost environments, including those environments where formation temperature of at least one formation is at or below about 32xc2x0 F. These compositions may be surprisingly formulated with materials as described elsewhere herein, but may also include at least one metal sulfate, such as aluminum and/or ferric sulfate, further increasing performance at low temperatures (e.g., compressive strength, shortened pump times, etc.), while at the same time producing cement compositions that exhibit heat of hydration values comparable or reduced as compared to comparable conventional cement compositions. In various embodiments, these compositions may be formulated to exhibit reduced heat of hydration as compared to conventional gypsum/Portland cementing compositions designed for permafrost environments. By so controlling or reducing BTU output during hydration, quality of cement bonding in, for example, areas of permafrost formations may be advantageously enhanced.
In one embodiment, such a method of cementing within a wellbore located in a permafrost environment includes introducing a cement slurry including a hydraulic cement, aluminum silicate (e.g., metakaolin, high reactivity metakaolin (xe2x80x9cHRMxe2x80x9d), etc.), and aluminum sulfate. The hydraulic cement (such as API Class G cement) may be present in an amount of from about 50% to about 85%, alternatively from about 68% to about 77% BWOB, although greater and lesser amounts (outside these ranges) are also possible, for example, lesser amounts may be present with the increased concentrations of other dry components. Aluminum silicate may be blended with the hydraulic cement in a concentration of, for example, from about 1% BWOC to about 50% BWOC, and aluminum sulfate may be blended with the hydraulic cement in a concentration of, for example, from about 1% BWOC to about 10% BWOC. Optional accelerators may be employed including, but not limited to, from about 1% to about 20% by weight of mix water (xe2x80x9cBWOWxe2x80x9d) of NaCl, and/or from about 1% BWOC to about 5% BWOC of CaCl2.
In another respect, disclosed is a method of cementing within a wellbore located in a seafloor at a water depth greater than about 1000 feet, including the steps of introducing a cement slurry including a hydraulic cement and aluminum silicate into a wellbore, and allowing the cement slurry to set within the wellbore. The cement slurry may be introduced into an annulus existing between a pipe and the wellbore. The cement slurry may be allowed to set at a temperature of less than about 60xc2x0 F. Advantageously, the cement slurry substantially prevents o intrusion of fluids into the wellbore prior to and after setting of the cement slurry. The cement slurry may include between about 1% and about 75% of aluminum silicate BWOC. The cement slurry may further include gypsum, and/or a foaming agent and energizing phase. The aluminum silicate may include at least one of kaolin, metakaolin, halloysite, dickite, nacrite, or a mixture thereof. In one embodiment, the aluminum silicate includes metakaolin. Advantageously, the cement slurry may have a transition time of about 35 minutes or less at a temperature of about 50xc2x0 F.
In another respect, disclosed is a method of cementing within a wellbore, including the steps of introducing a cement slurry including a hydraulic cement and aluminum silicate into a wellbore, and allowing the cement slurry to set within the wellbore at a temperature of less than about 60xc2x0 F. The cement slurry may be introduced into an annulus existing between a pipe and the wellbore. Advantageously, the cement slurry may substantially prevent intrusion of fluids into the wellbore prior to and after setting of the cement slurry. The cement slurry may include between about 1% and about 75% of aluminum silicate BWOC. The cement slurry may further include gypsum and/or a foaming agent and energizing phase. The aluminum silicate may include at least one of kaolin, metakaolin, halloysite, dickite, nacrite, or a mixture thereof. In one embodiment, the aluminum silicate includes metakaolin. Advantageously the cement slurry may have a transition time of about 35 minutes or less at a temperature of about 500xc2x0 F.
In another respect, disclosed is a method of cementing within a wellbore located in a seafloor at a water depth greater than about 1000 feet. The method includes the steps of introducing a cement slurry including a hydraulic cement, between about 1% and about 25% metakaolin BWOC, and a foaming agent and energizing phase into an annulus existing between a pipe and the wellbore, and allowing the cement slurry to set within the wellbore. Advantageously, the cement slurry may substantially prevent intrusion of fluids into the wellbore prior to and after setting of the cement slurry. The cement slurry may be allowed to set at a temperature of less than about 60xc2x0 F. The cement slurry may further include between about 1% and about 15% of gypsum BWOC, and/or may include from about 0.01 GPS to about 0.5 GPS of foaming agent and from about 50 SCF/bbl to about 2000 SCF/bbl of nitrogen energizing phase. Advantageously, the cement slurry may have a transition time of about 40 minutes or less at a temperature of about 50xc2x0 F.
In another respect, disclosed is a method of cementing within a wellbore in which the wellbore penetrates at least one formation having a pore pressure and is at least partially productive of a fluid. The method includes the steps of introducing a cement slurry including a hydraulic cement and aluminum silicate into a wellbore, and allowing the cement slurry to set within the wellbore. Advantageously, the cement slurry may substantially prevent intrusion of the fluid into the into the wellbore prior to and after setting of the cement slurry. The cement also substantially prevent intrusion of the fluid into the wellbore prior to setting of the cement when the cement pore pressure is less than the formation pore pressure; In some cases, the formation may be productive of a fluid that is gas. The cement slurry may be introduced into an annulus existing between a pipe and the wellbore. The cement slurry may include between about 1% and about 75% of aluminum silicate BWOC, and may optionally further include gypsum. The aluminum silicate may include at least one of kaolin, metakaolin, halloysite, dickite, nacrite, or a mixture thereof. In one embodiment, the aluminum silicate may include metakaolin, and in another embodiment may include high reactivity metakaolin.
In another respect, disclosed is a method of cementing within a wellbore, including the steps of introducing a cement slurry including a hydraulic cement and aluminum silicate into a wellbore, and allowing the cement slurry to set within the wellbore. In this method the aluminum silicate may include at least one of kaolin, metakaolin, halloysite, dickite, nacrite, or a mixture thereof. In one embodiment the aluminum silicate includes metakaolin. The slurry may have a slurry density of between about 11.5 lbm/gal and about 13.5 lbm/gal.
In another respect, disclosed is a well cementing composition including a hydraulic cement and aluminum silicate. In various exemplary embodiments, a composition may include greater or equal to about 25%, alternatively greater than or equal to about 30%, alternatively greater than or equal to about 40%, alternatively greater than or equal to about 50%, and alternatively greater than or equal to about 60% by weight of one cubic foot of hydraulic cement, in addition to aluminum silicate. The hydraulic cement may be any of the hydraulic cements mentioned elsewhere herein. In this composition, the aluminum silicate may include at least one of kaolin, metakaolin, halloysite, dickite, nacrite, or a mixture thereof. In one embodiment, the aluminum silicate includes metakaolin. The aluminum silicate may be present in any amount disclosed elsewhere herein. Furthermore, any of the cementing additives mentioned elsewhere herein may be employed.
In another respect, disclosed is a method of cementing within a wellbore, including introducing a cement slurry including effective amounts of hydraulic cement, aluminum silicate and metal sulfate into a wellbore; and allowing the cement slurry to cure within the wellbore; wherein the hydraulic cement, the aluminum silicate and the metal sulfate are present in the cement slurry in amounts effective to formulate a wellbore cement.
In another respect, disclosed is a method of cementing within a wellbore, including introducing a cement slurry including effective amounts of hydraulic cement, high reactivity metakaolin, and aluminum sulfate into a wellbore; and allowing the cement slurry to cure within the wellbore; wherein the cement slurry is formulated from a cement composition including greater than or equal to about 50% Portland cement by weight of total dry blend prior to addition of water; and wherein the hydraulic cement, the high reactivity metakaolin and the aluminum sulfate are present in the cement slurry in amounts effective to formulate a wellbore cement.
In another respect, disclosed is a well cementing composition including hydraulic cement, high reactivity metakaolin, and aluminum sulfate; wherein the hydraulic cement, the high reactivity metakaolin and the aluminum sulfate are present in the composition in amounts effective to formulate a wellbore cement.